CN109153919B

CN109153919B - Enhanced steam extraction of bitumen from oil sands

Info

Publication number: CN109153919B
Application number: CN201780029659.1A
Authority: CN
Inventors: C·A·威瑟姆; B·慕克吉
Original assignee: Dow Global Technologies LLC
Current assignee: Dow Global Technologies LLC
Priority date: 2016-05-26
Filing date: 2017-05-18
Publication date: 2021-07-16
Anticipated expiration: 2037-05-18
Also published as: RU2018143890A; RU2746846C2; US10633593B2; US20190119577A1; CA3025272A1; RU2018143890A3; WO2017205179A1; CA3025272C; CN109153919A

Abstract

The present invention relates to an improved process for recovering bitumen from oil sands. The oil sands may be surface mined and transported to a treatment area or may be directly treated by in situ processing of oil sands deposits that are located too deep to be surface mined. Specifically, the present invention comprises the step of treating oil sands with ethylene oxide capped glycol ethers described by the following structure: RO- (CH)₂CH(CH₃)O)_m(C₂H₄O)_nH wherein R is a linear, branched, cyclic alkyl, phenyl or alkylphenyl of greater than 5 carbons, and m and n are independently 1 to 3.

Description

Enhanced steam extraction of bitumen from oil sands

Technical Field

The present invention relates to the recovery of bitumen from oil sands. More specifically, the present invention is an improved process for recovering bitumen from oil sands by surface mining or in situ recovery. The improvement is the use of ethylene oxide capped glycol ethers as extraction aids in water and/or steam used in the bitumen recovery process.

Background

Oil sands deposits are found around the world, but the most prominent are canada, venezuela, and the united states. Such oil sands contain large deposits of heavy oil, commonly referred to as bitumen. Bitumen from such oil sands can be extracted and refined into synthetic oil or directly into petroleum products. The difficulty is that bitumen is generally very viscous and sometimes not as solid as it is a liquid. Thus, bitumen generally does not flow as much as less viscous or light crude oil.

Because of the viscosity of bitumen, it cannot be produced in wells drilled into oil sands, as in light crude oil. This is because bitumen does not flow without first being heated, diluted and/or upgraded. Since normal oil drilling practices are insufficient to produce bitumen, several methods have been developed over the decades to extract and process oil sands to remove bitumen. For shallow deposits of oil sands, typical methods include surface extraction or mining followed by treatment of the oil sands to remove the bitumen.

The development of surface extraction processes occurs most extensively in the academy of Athabasca (Athabasca) oil field. In such processes, oil sands are typically mined by strip mining (open pit mining), with draglines, bucket-wheel excavators, and more recently, scraper operations. The oil sands are then transported to a facility for processing and removal of bitumen from the sand. These processes typically involve some type of solvent, most commonly water or steam, although other solvents, such as hydrocarbon solvents, have been used.

After excavation, hot water extraction processes are commonly used in athabasca oil fields, where oil sands are mixed with water at temperatures of about 35 ℃ to 75 ℃, with recent improvements lowering the required temperature to the lower range. An extractant, such as sodium hydroxide (NaOH), a surfactant, and/or air, may be mixed with the oil sands.

Water is added to oil sands to produce an oil sands slurry, to which additives such as NaOH can be added, which is then transported, typically via a pipeline, to an extraction facility. Within the separation vessel, the slurry is agitated and water and NaOH release bitumen from the oil sands. The air entrained with the water and NaOH adheres to the bitumen, floating it to the top of the slurry mixture and creating a froth. The bitumen froth is further treated to remove residual water and fines, which are typically small sand and clay particles. The bitumen is then stored for further processing or immediate processing, chemically treated or mixed with light petroleum products and transported through pipelines for upgrading to synthetic crude oil. Unfortunately, this method cannot be used for deeper tar sands layers. In situ techniques are necessary for the recovery of deep oil in well production. It is estimated that approximately 80% of the Alberta (Alberta) tar sands and almost all venezuelan tar sands are located too deep below the surface of the earth to be used for open pit mining.

In well production, which is referred to as in situ recovery, Steam Stimulation (CSS) is a traditional "Stimulation" in situ method in which Steam is injected into a well at a temperature of 250 ℃ to 400 ℃. The steam rises and heats the bitumen, reducing its viscosity. The well is allowed to stand for days or weeks and then the hot oil mixed with condensed steam is pumped out for a period of weeks or months. The process is then repeated. Unfortunately, the "throughput" method requires shutting down the site for weeks to allow the pumpable oil to accumulate. In addition to the high cost of steam injection, CSS processes typically result in a usable oil recovery of 20 to 25 percent.

Steam Assisted Gravity Drainage (SAGD) is another in situ process in which two horizontal wells are drilled in the tar sands, one at the bottom of the formation and the other five meters above. The wells are drilled from the center pad groupings. These wells may extend miles in all directions. Steam is injected into the upper well, thereby melting the bitumen, which then flows into the lower well. The resulting liquid oil mixed with condensed vapor is then pumped to the surface. Typical recovery of usable oil is 40% to 60%.

There are many cost, environmental and safety issues associated with the above approaches. For example, the use of large amounts of steam is energy intensive and requires the disposal and disposal of large amounts of water. Currently, tar sand extraction and processing requires several barrels of water per barrel of oil produced. Strip mining and further processing produce incompletely cleaned sand which requires further processing before it can be returned to the environment. Furthermore, the use of large amounts of caustic in surface mining not only presents a process safety hazard but also promotes the formation of fine clay particles in the tailings, disposal of which is a major environmental concern.

Thus, there remains a need for an efficient, safe, and cost-effective process for improving the recovery of bitumen from oil sands.

Disclosure of Invention

The present invention is an improved bitumen recovery process comprising the step of treating oil sands with ethylene oxide capped glycol ethers, wherein the treatment is of oil sands recovered by surface mining or in situ production of oil sands in subterranean reservoirs.

In one embodiment of the bitumen recovery process described above, the ethylene oxide-capped glycol ether is described by the following structure:

RO-(CH₂CH(CH₃)O)_m(C₂H₄O)_n H

wherein R is a linear, branched, cyclic alkyl, phenyl or alkylphenyl group of greater than 5 carbons, preferably n-butyl, n-pentyl, 2-methyl-1-pentyl, n-hexyl, n-heptyl, n-octyl, 2-ethylhexyl, 2-propylheptyl, phenyl or cyclohexyl, and m and n are independently 1 to 3, preferably the ethylene-capped glycol ether is one of or a combination of the following, preferably ethylene oxide-capped propylene glycol n-butyl ether, ethylene oxide-capped propylene glycol n-hexyl ether or ethylene oxide-capped propylene glycol 2-ethylhexyl ether.

In another embodiment of the invention, the bitumen recovery process by surface mining as described above comprises the steps of: i) oil sand is exploited on the surface; ii) preparing an oil sand aqueous slurry; iii) treating the aqueous slurry with an ethylene oxide-capped glycol ether; iv) agitating the treated aqueous slurry, v) transferring the agitated treated aqueous slurry to a separation tank; and vi) separating the bitumen from the aqueous portion, preferably the ethylene oxide capped glycol ether is present in the aqueous slurry in an amount of from 0.01 to 10 wt% by weight of the oil sands.

In another embodiment of the present invention, the asphalt recovery process by in situ production as described above comprises the steps of: i) treating a subterranean oil sands reservoir by injecting steam containing an ethylene oxide-capped glycol ether into the well; and ii) recovering bitumen from the well, preferably in an amount such that the concentration of the ethylene oxide-capped glycol ether in the steam is from 100ppm to 10 wt%.

Drawings

FIG. 1 is a graph showing oil recovery versus time for an example of the inventive process and an example of a process that is not the inventive process.

Detailed Description

Separation of bitumen and/or heavy oil from oil sands is accomplished by, but is not limited to, two methods: surface mining or in situ recovery (sometimes referred to as well production). Oil sands may be recovered by surface or open pit mining and transported to a disposal area. A good summary can be found in the article "Understanding the Water-Based Bitumen Extraction from Athabasca Oil Sands from Water Extraction of Isaacs Oil Sands", Masliyah et al, Journal of Chemical Engineering in Canadian, volume 82, month 8 2004. The basic steps in the recovery of bitumen via surface mining include: extraction, foam treatment, tailing treatment and upgrading. The steps are interrelated; mining operations affect extraction, and extraction in turn affects lifting operations.

Typically, in commercial bitumen recovery operations, oil sands are mined in open pit mines using trucks and shovels. The mined oil sands are transported to a processing area. The extraction step comprises: the oil sand cake is crushed and mixed with water in a mixing tank, stirred tank, ring feeder or gyratory crusher (a recycling process) to form a conditioned oil sand slurry. The conditioned oil sand slurry is introduced into a hydraulic transport pipe or drum where the oil sand clumps are sheared and reduced in size. Within the bowl and/or hydraulic transport conduit, pitch is recovered or "released" or "liberated" from the sand particles. Chemical additives may be added during the slurry preparation stage; examples of chemicals known in the art are found in US 2008/0139418, which is incorporated herein by reference in its entirety. In a typical operation, the operating slurry temperature is in the range of 35 ℃ to 75 ℃, preferably 40 ℃ to 55 ℃.

In the drum and hydraulic transfer ducts, entrained or introduced air adheres to the bitumen, creating a froth. In the froth treatment step, the aerated bitumen floats and is then skimmed from the slurry. This step is accomplished in a large gravity separation vessel, commonly referred to as a Primary Separation Vessel (PSV), separation cell (Sep cell), or Primary Separation Cell (PSC). The small amount of bitumen droplets remaining in the slurry (typically unaerated bitumen) are further recovered in mechanical flotation cells and tailings oil recovery vessels or loop separators and hydrocyclones using induced air flotation. Generally, the overall bitumen recovery in a commercial operation is about 88 to 95% of the original oil in place. The recovered bitumen in the form of a froth typically contains 60% bitumen, 30% water and 10% solids.

The bitumen froth so recovered is then degassed and diluted (mixed) with a solvent to provide a sufficient density difference between the water and bitumen and to reduce the bitumen viscosity. Dilution with a solvent (e.g., naphtha or hexane) aids in the removal of solids and water from bitumen froth using inclined plate settlers, cyclones and/or centrifuges partial precipitation of asphaltenes occurs when a paraffinic diluent (solvent) is used at a sufficiently high diluent to bitumen ratio. This results in the formation of complex aggregates that entrap water and solids in the diluted bitumen froth. In this way, gravity separation is greatly enhanced, possibly without the need for cyclones or centrifuges.

In the tailings treatment step, the tailings flow from the extraction equipment enters a tailings pond for solid-liquid separation. The purified water is recycled from the tank to the extraction apparatus. To speed up tailings treatment, gypsum may be added to mature fine tailings to consolidate the fines together with the coarse sand into a non-segregated mixture. This process is known as consolidated (composite) tailings (CT) process. CT is disposed of in an earthwork fashion that facilitates its further dehydration and ultimate recovery. Optionally, tailings from the extraction plant are subjected to a cyclone, the overflow (fine tailings) is pumped to a thickener and the cyclone underflow (coarse tailings) is pumped to a tailings pond. The fine tailings are treated with a flocculant and subsequently thickened and pumped to a tailings pond. In addition, the use of paste technology (addition of flocculant/polyelectrolyte) or a combination of CT and paste technology can be used to rapidly release water and recycle the water in the CT to the extraction equipment to recover bitumen from the oil sands.

In the final step, the recovered bitumen is upgraded. Upgrading either adds hydrogen or removes carbon to obtain the more valuable and more refined balance of light hydrocarbons. The upgrading process also removes contaminants such as heavy metals, salts, oxygen, nitrogen, and sulfur. The upgrading process includes one or more steps, such as: distillation, wherein the various compounds are separated by physical properties; coking; performing hydro-conversion; solvent deasphalting to increase the hydrogen to carbon ratio; and hydrotreating to remove contaminants such as sulfur.

In one embodiment of the invention, the improvement in the process for recovering bitumen from oil sands is the addition of an ethylene oxide-capped glycol ether during the slurry preparation stage. The slurried material is added to a slurry tank with agitation and combined with an ethylene oxide capped glycol ether. The ethylene oxide-capped glycol ether can be added to the oil sand slurry neat or as an aqueous solution having an ethylene oxide-capped glycol ether concentration of 100ppm to 10 weight percent, based on the total weight of the ethylene oxide-capped glycol ether solution. Preferably, the ethylene oxide-capped glycol ether is present in the aqueous oil sand slurry in an amount of from 0.01 to 10 weight percent based on the weight of the oil sand.

Preferred ethylene oxide capped glycol ethers of the present invention are represented by the formula:

RO-(CH₂CH(CH₃)O)_m(C₂H₄O)_n H

wherein R is a linear, branched, cyclic alkyl, phenyl or alkylphenyl group of more than 5 carbons, preferably n-butyl, n-pentyl, 2-methyl-1-pentyl, n-hexyl, n-heptyl, n-octyl, 2-ethylhexyl, 2-propylheptyl, phenyl or cyclohexyl,

and is

m and n are independently 1 to 3.

As used hereinafter, the ethylene oxide-capped glycol ethers of the present invention refer to ethylene oxide caps comprising 1 to 3 ethylene oxide units. Preferred ethylene oxide-capped glycol ethers are ethylene oxide-capped propylene glycol n-butyl ether, ethylene oxide-capped dipropylene glycol n-butyl ether, ethylene oxide-capped tripropylene glycol n-butyl ether, ethylene oxide-capped propylene glycol n-pentyl ether, ethylene oxide-capped dipropylene glycol n-pentyl ether, ethylene oxide-capped tripropylene glycol n-pentyl ether, ethylene oxide-capped propylene glycol 2-methyl-1-pentyl ether, ethylene oxide-capped dipropylene glycol 2-methyl-1-pentyl ether, ethylene oxide-capped tripropylene glycol 2-methyl-1-pentyl ether, ethylene oxide-capped propylene glycol n-hexyl ether, ethylene oxide-capped dipropylene glycol n-hexyl ether, ethylene oxide-capped tripropylene glycol n-heptyl ether, ethylene oxide-capped dipropylene glycol n-heptyl ether, ethylene oxide-capped propylene glycol n-heptyl ether, ethylene oxide-capped tripropylene glycol n-heptyl ether, ethylene oxide-capped propylene glycol n-heptyl ether, ethylene oxide-capped, Ethylene oxide-capped tripropylene glycol n-heptyl ether, ethylene oxide-capped propylene glycol n-octyl ether, ethylene oxide-capped dipropylene glycol n-octyl ether, ethylene oxide-capped tripropylene glycol n-octyl ether, ethylene oxide-capped propylene glycol 2-ethylhexyl ether, ethylene oxide-capped dipropylene glycol 2-ethylhexyl ether, ethylene oxide-capped tripropylene glycol 2-ethylhexyl ether, ethylene oxide-capped propylene glycol 2-propylheptyl ether, ethylene oxide-capped dipropylene glycol 2-propylheptyl ether, ethylene oxide-capped tripropylene glycol 2-propylheptyl ether, ethylene oxide-capped propylene glycol phenyl ether, ethylene oxide-capped dipropylene glycol phenyl ether, ethylene oxide-capped tripropylene glycol phenyl ether, ethylene oxide-capped propylene glycol cyclohexyl ether, ethylene oxide-capped dipropylene glycol cyclohexyl ether, Ethylene oxide-capped tripropylene glycol cyclohexyl ether, or mixtures thereof.

The ethylene oxide-capped glycol ether solution/oil sands slurry is typically stirred for 5 minutes to 4 hours, preferably 1 hour or less. Preferably, the ethylene oxide capped glycol ether solution oil sand slurry is heated to equal to or greater than 35 ℃, more preferably equal to or greater than 40 ℃, more preferably equal to or greater than 55 ℃, more preferably equal to or greater than 60 ℃. Preferably, the ethylene oxide capped glycol ether solution oil sand slurry is heated to equal to or less than 100 ℃, more preferably equal to or less than 80 ℃, and more preferably equal to or less than 75 ℃.

As outlined above, the ethylene oxide capped glycol ether treated slurry can be transferred to a knockout drum, which typically contains a dilute detergent solution, wherein bitumen and heavy oil are separated from the aqueous portion. The solid and aqueous portions may be further treated to remove any additional free organic matter.

In another embodiment of the invention, bitumen is recovered from oil sands by well production, wherein ethylene oxide capped glycol ethers as described above can be added to the oil sands by in situ treatment of oil sands deposits that are located too deep to be surface mined. The two most common methods of in situ production recovery are steam stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD). CSS may utilize vertical and horizontal wells that alternately inject steam and pump heated bitumen to the surface, creating a cycle of injection, heating, flow, and extraction. SAGD utilizes pairs of horizontal wells, one above the other in the bitumen producing zone. The upper well is used to inject steam, creating a permanent heating chamber in which the heated bitumen flows by gravity to the lower well from which the bitumen is extracted. However, new technologies such as vapor recovery extraction (VAPEX) and sand production cold production with sand (CHOPS) are under development.

The basic steps of an in situ process for recovering bitumen from oil sands include: a steam injection well; recovering bitumen from the well; and diluting the recovered bitumen, for example with condensate, for transport through a pipeline.

According to this method, ethylene oxide capped glycol ethers are used as steam additives in bitumen recovery processes for subterranean oil sands reservoirs. In single or multi-well plans, the pattern of steam injection may include one or more of steam drive, steam soak, or periodic steam injection. In addition to one or more of the steam injection methods listed above, a water flooding method may also be used.

Typically, steam is injected into an oil sands reservoir through an injection well, and formation fluids, including the reservoir and the injection fluid therein, are produced through an adjacent production well or by reverse flow back into the injection well.

In most oil sands reservoirs, a steam temperature of at least 180 ℃ is required, which corresponds to a pressure of 150psi (1.0MPa) or higher, to move the bitumen. Preferably, the ethylene oxide-capped glycol ether-steam injection stream is introduced into the reservoir at a temperature of from 150 ℃ to 300 ℃, preferably from 180 ℃ to 260 ℃. The particular steam temperature and pressure used in the method of the invention will depend on the particular reservoir characteristics, such as depth, overburden formation pressure, pay zone thickness, and bitumen viscosity, and will therefore be tailored for each reservoir.

The ethylene oxide-capped glycol ether is preferably injected simultaneously with the steam to ensure or maximize the amount of ethylene oxide-capped glycol ether that actually moves with the steam. In some cases, it may be desirable to inject a steam-only injection stream before or after the steam-ethylene oxide capped glycol ether injection stream. In this case, the steam temperature may rise above 260 ℃ during the steam injection only. The term "steam" as used herein is meant to include superheated steam, saturated steam, and less than 100% quality steam.

For clarity, the term "less than 100% quality vapor" refers to vapor in which a liquid aqueous phase is present. The vapor quality is defined as the weight percentage of dry vapor contained in a unit weight of the vapor-liquid mixture. "saturated steam" is used synonymously with "100% quality steam". "superheated steam" is steam that has been heated above the vapor-liquid equilibrium point. If superheated steam is used, the steam is preferably superheated to 5 to 50 ℃ above the vapor-liquid equilibrium temperature prior to addition of the ethylene oxide capped glycol ether.

The ethylene oxide-capped glycol ether can be added to the steam neat or in the form of a concentrate. If added as a concentrate, it can be added as a 1 to 99 weight percent aqueous solution. Preferably, the ethylene oxide-capped glycol ether is substantially volatile and enters the reservoir as an aerosol or mist. Again, the reason here is to maximize the amount of ethylene oxide capped glycol ether that enters the reservoir with the steam.

The ethylene oxide-capped glycol ether is preferably injected intermittently or continuously with steam such that the steam-ethylene oxide-capped glycol ether injection stream reaches the downhole formation through a common pipe. The rate of addition of the ethylene oxide-capped glycol ether is adjusted to maintain the preferred concentration of ethylene oxide-capped glycol ether in the steam of 100ppm to 10 weight percent. Steam injection rates for typical oil sands reservoirs may be 1 to 3 feet per day so that there is enough steam to provide propulsion through the formation.

An effective SAGD additive must meet a number of requirements in order to be considered successful. The primary criteria for successful additives is that the additives move with the steam and reach the unrecovered in-situ bitumen in the reservoir, advantageously interacting with the water/bitumen/rock to enhance bitumen recovery, without adversely interfering with the ability of existing operations. Among the three, the requirement that the additive vaporize and move with the steam at the SAGD operating temperature limits the selection and consideration of different chemicals in SAGD technology. For example, many high molecular weight surfactants, even if known to help improve oil recovery, are not considered SAGD additives because they cannot move with steam due to their high boiling points. However, many ethylene oxide-capped glycol ethers with boiling points higher than water are exceptions. Phase equilibrium studies have shown that the distribution of such materials in vapor (i.e., steam) is advantageous compared to liquid (i.e., water) phase. The more unique ability to partition in the vapor comes from the ability of the various ethylene oxide-capped glycol ethers to form a water-additive azeotrope, particularly when present in low concentrations, and thus many ethylene oxide-capped glycol ethers, including those mentioned in this example, are able to move with the vapor.

Examples of the invention

Comparative example a contained only water. Examples 1 to 4 and comparative example B are described by the following structures:

RO-(CH₂CH(CH₃)O)_m(C₂H₄O)_n H。

for comparative examples a and B and examples 1 to 4, oil recovery and interfacial tension (IFT) between oil and water were determined at two different temperatures and the results are shown in table 1.

Interfacial tension test

IFT was measured using a Tracker dynamic drop tensiometer equipped with a battery, in order to perform the measurements at high temperature and high pressure (up to 200 ℃ and 200 bar). The oil used to screen the new formulations consisted of dodecane and toluene in a 50:50 weight ratio. And pumping the oil sample to be tested into the syringe. Next, the "J" crochet needle was placed on the syringe. The syringe is then mounted in a cradle within the pressure cell. The cuvette was filled with deionized water and the required amount of additive (typically 2000ppm) and placed in a holder inside a pressure cell. The cuvette is placed with the tip of the syringe immersed in the fluid contained within the cuvette. The pressure cell assembly is completed and then placed on the Tracker instrument. The cartridge is heated to the desired measurement temperature (in the range of 110-. Upon reaching the desired set point temperature, the oil is pushed out of the syringe needle to form a stable droplet at the needle tip. Droplets of about 10. mu.L in volume were formed. All measurements were taken within 400 seconds of droplet formation so that equilibrium was achieved. IFT values were recorded and measurements were repeated 2 to 3 times. Data are reported as the average of all measurements. Subsequently, an additional temperature set point for a given recipe is measured. The experimental uncertainty of the IFT measurement is less than 1.0 dyn/cm.

Steam soaking

The steam soak experiments were performed as follows. A500 mL Parr reactor was charged with about 150mL of water or a 2.5 wt% additive/water mixture. A synthetic oil sand core prepared by mechanical compression of 50g of mined oil sand was placed in a basket and hung on the lid of a Parr reactor so that the core did not contact the liquid phase at the bottom. The reactor was sealed and then heated to 188 ℃ for 4 hours. After cooling the reactor overnight, the produced oil and waste sand were analyzed to determine oil recovery. The experimental uncertainty of the steam soak data is less than 5 wt%.

TABLE 1

Balanced distribution

In example 5, the equilibrium distribution of hexanol propoxyethoxylate (where R is hexyl, m is 1, and n is 1) was measured at elevated temperature in a vapor-liquid equilibrium system. 350g of water and 350g of tert-butylbenzene containing 8000ppm of hexanol propoxyethoxylate were charged to a 1.8L Lab Max stirred tank reactor. Small aliquots of the vapor phase, organic (TBB) phase and aqueous phase were sampled at 150 ℃, 175 ℃ and 200 ℃. The concentration of hexanol propoxyethoxylate was measured by gas chromatography equipped with FID. The concentration of hexanol propoxyethoxylate in each phase is shown in table 2. K at 175 ℃ and 200 ℃_V/AValues greater than 1 indicate the presence of a positive azeotrope.

TABLE 2

Gravity oil drainage

The effect of the additive on bitumen recovery was studied using a gravity drainage apparatus and compared to a baseline (i.e. without any additive). The gravity drainage device consists of a cylindrical steam chamber in which a synthetic sand core saturated with bitumen is suspended along the central axis of the top plate of the steam chamber. A synthetic core (size 1.5 "x 6"; DXH) is located within the basket so that the steam or steam plus additives can easily diffuse and interact with the core from all directions. High temperature, high pressure steam (comparable to SAGD steam chamber conditions) is then injected along the annular space within the steam chamber. The steam or steam plus additives diffuse and interact with the core and cause the bitumen and condensed steam to gravitate out at the bottom of the chamber and collect as a function of time. The chamber pressure is controlled and kept constant using a back pressure regulator. The experiment provides information on oil recovery (i.e. the percentage of crude oil recovered as a function of time (OOIP)) and total oil recovered at the end of the experiment (i.e. oil displaced over time plus recovered oil along the chamber walls and pipelines). The experiment lasted 5.5 hours and was operated under the same temperature and pressure conditions.

Comparative example a contained no additive, i.e. only steam, and example 6 was steam plus hexanol propoxy ethoxylate. The results with respect to time are shown in fig. 1. The total oil recovery of example 6 was 46 wt%, while the total oil recovery of comparative example a was 21 wt%.

Claims

1. A process for recovering bitumen comprising the step of contacting oil sands with an ethylene oxide capped glycol ether described by the following structure:

RO-(CH₂CH(CH₃)O)_m(C₂H₄O)_n H

wherein R is a linear, branched, cyclic alkyl, phenyl or alkylphenyl group of greater than 5 carbons,

and is

m is independently 1 to 3, and n is 1;

where oil sands recovered by surface mining or in situ production are treated.

2. The method of claim 1, utilizing surface mining, the method comprising the steps of:

i) oil sand is exploited on the surface;

ii) preparing an aqueous slurry of the oil sands;

iii) treating the aqueous slurry with the ethylene oxide-capped glycol ether;

iv) agitating the treated aqueous slurry,

v) transferring the agitated treated aqueous slurry to a separation tank;

and

vi) separating the bitumen from the aqueous fraction.

3. The process of claim 2 wherein the ethylene oxide-capped glycol ether is present in the aqueous slurry in an amount of from 0.01 to 10 weight percent based on the weight of the oil sands.

4. The method of claim 1, which utilizes in situ production, the method comprising the steps of:

i) treating a subterranean oil sands reservoir by injecting steam containing the ethylene oxide-capped glycol ether into the well;

and

ii) recovering the bitumen from the well.

5. The method of claim 4, wherein the concentration of the ethylene oxide-capped glycol ether in the steam is in an amount of 100ppm to 10 wt.%.

6. The method of claim 1 wherein the ethylene oxide-capped glycol ether is ethylene oxide-capped propylene glycol n-hexyl ether or ethylene oxide-capped propylene glycol 2-ethylhexyl ether.